In Integrated Coal Gasification Combined Cycle (IGCC) power plants the fuel gas from the O.sub.2 blown coal gasification has to be desulfurized before being combusted in the gas turbine for power generation. When the gas is produced by proven coal gasification processes using a 60 wt % coal in water slurry feed, it contains about 20 (dry) mole % CO.sub.2 with a sulfur content depending on the coal fed. With a low sulfur coal containing 0.5 wt % sulfur the fuel gas contains about 0.15 mole % H.sub.2 S and about 0.003 mole % COS. To achieve desired SO.sub.2 emission limits, 97% of H.sub.2 S+ COS must be removed and recovered as elemental sulfur in a Claus plant and tail gas cleanup unit (TGCU). A selective acid gas removal process is required to absorb essentially all the H.sub.2 S while coabsorbing a minimum amount of CO.sub.2. Minimum CO.sub.2 removal is required to obtain a concentrated H.sub.2 S Claus plant feed to minimize the capital and operating costs of the Claus plant and TGCU. Co-absorbtion of CO.sub.2 not only dilutes the Claus H.sub.2 S feed, it also decreases the IGCC power generation thermal efficiency. The CO.sub.2 in the high pressure fuel gas generates power when it is expanded in the gas turbine. To the extent that CO.sub.2 is removed with the H.sub.2 S. that power generation potential is lost. The problem is that available acid gas removal processes are not sufficiently selective and co-absorb significant CO.sub.2. The most selective physical solvents, such as mixed dialkylethers of polyethylene gylcol and N methyl pyrrolidone coabsorb about 16% of the CO.sub.2 when solvent flow is set to remove essentially all of the H.sub.2 S. With low sulfur coal gasification gas, this results in a very dilute (5 to 6 mole % H.sub.2 S) acid gas which can not be processed in a conventional Claus plant. In commercial practice an expensive H.sub.2 S selective amine preconcentration is used to increase the Claus feed to 25% H.sub.2 S. Even at this concentration the TGCU is very expensive and natural gas fuel has to be fired to raise Claus reaction furnace temperature to an acceptable level.
The problem overcome by the present invention is development of an IGCC desulfurization system that gives a concentrated H.sub.2 S Claus/TGCU feed and retains CO.sub.2 in the fuel gas to the gas turbine to maximize power generation thermal efficiency.
The problem has been recognized by the Electric Power Research Institute (EPRI) who commissioned a study to contact experts skilled in the art of gas processing to identify promising new approaches to solve it. The study by SFA Pacific Inc. is summarized in a final report EPRI AP-5505, Project 2221-13. December 1987. Table 3-6 of the report summarizes performance data supplied by licensors of selective physical solvent and amine acid gas removal processes for low sulfur coal gasification feeds. The processes, in general obtained Claus feeds with 5 to 8% H.sub.2 S, except for the Purisol process which achieved 40% H.sub.2 S. Page 3-15 from the report, notes that the Purisol design included an N.sub.2 stripping stage to enrich the Claus plant acid gas feed from 6.5 to 40% H.sub.2 S. It states that such a stripper is used in the Texaco. Wilmington refinery Rectisol process described in their reference "The Rectisol Process . . .", Gerhard Ranke. Chemical Economy and Engineering Review, May 1972. Vol. 4 No. 5 (No. 49) pp. 25-31. The H.sub.2 S enrichment column is shown on FIG. 4, page 29. It operates at essentially atmospheric pressure and includes a bottom CO.sub.2 stripping section surmounted by an H.sub.2 S reabsorber section. In operation it uses N.sub.2 to strip some of the CO.sub.2 from the solvent with H.sub.2 S in the stripped CO.sub.2 reabsorbed with H.sub.2 S-free solvent in the top reabsorber section to give an N.sub.2 plus CO.sub.2 vent stream containing an acceptable 10 ppm of H.sub.2 S. While operation at low pressure minimizes the N.sub.2 strip gas requirement which is directly proportional to pressure, it increases the solvent flow required to reabsorb the H.sub.2 S which is inversely proportional to operating pressure. As stated on page 25 of Ranke, with physical solvent processes, absorption solvent flow is in general inversely proportional to pressure. Because the reabsorbtion solvent flow is added to the main absorber solvent for regeneration, it increases the regeneration steam requirement. When the process operates at refrigerated temperature, as many physical solvent processes such as Rectisol and Selexol do, and Purisol may, the increased regeneration solvent flow increases the refrigeration requirements. As a result, N.sub.2 stripping at low pressure to obtain a concentrated Claus H.sub.2 S stream is unattractive because regeneration solvent flows are excessive and result in prohibitive solvent regeneration steam and refrigeration requirements. Also, the stripped carbon dioxide along with the nitrogen strip gas is rejected to the atmosphere and does not contribute to power production in the gas turbine. Finally, note that the solvent regeneration severity has to be increased to obtain very low residual hydrogen sulfide content in the lean regenerated solvent to achieve the 10 ppm hydrogen sulfide level in the reabsorber carbon dioxide and nitrogen vent gas at low pressure.
U.S. Pat. No. 4,242,108 to Nicholas & Hegarty assigned to the present assignee solves the problem of obtaining a concentrated Claus H.sub.2 S feed gas by heating the H.sub.2 S absorber bottoms solvent and feeding it to a high pressure CO.sub.2 stripping column operating at essentially the same pressure as the H.sub.2 S absorber and stripping the coabsorbed CO.sub.2 with a high pressure CO.sub.2 -free inert gas. It notes the possibility of using high pressure N.sub.2 from an air separation unit (Col. 3. lines 7-9) in NH.sub.3 plant applications. In general, it is not feasible to use nitrogen stripping gas, with the nitrogen contaminating the treated gas. This citation of N.sub.2 use is limited to NH.sub.3 applications where N.sub.2 has to be compressed and added to the H.sub.2 after acid gas removal to make NH.sub.3 synthesis gas. This application merely routes a portion of the required N.sub.2 through the stripper for beneficial effects. It is limited in the claims to situations where CO.sub.2 has to be rejected from the product gas as in NH.sub.3 synthesis.
Note also that because the strip gas requirement is directly proportional to the stripper pressure, high pressure N.sub.2 stripping requirements result in high N.sub.2 compression requirements, except for NH.sub.3 synthesis applications where the N.sub.2 must be compressed in any event.
Hot stripping at high pressure and temperature also increases refrigeration requirements for refrigerated physical solvent processes. In the Nicholas and Hegarty patent, while the lean solvent is precooled against stream 7 in heat exchanger 8, stream 7 has not been cooled by expansion and flashing as is typically done. As a result with a given cold end temperature approach in exchanger 8, the lean solvent temperature is increased and this results in an increase in net process refrigeration duty. Also operation of heat exchanger 8 precludes the use of the economical plate and frame type heat exchanger which have gaskets limited to pressures below 300 psig.